Seismic surveys are useful for studying subsurface formations in many contexts, including the monitoring of subsurface hydrocarbon reservoirs and the tracking of fluids, e.g. oil, gas, or water, as they flow through the subsurface strata. One type of areal monitoring that is gaining in importance is the ability to track CO2 that has been injected as part of carbon capture and sequestration (CCS) projects. Also of interest in the context of subsurface monitoring are the various fluids that are used for enhanced oil recovery (EOR), hydrocarbon saturation, fraccing operations, and the like.
Conventional seismic monitoring is typically multi-dimensional, with three dimensions relating to the spatial characteristics of the earth formation. Typically two dimensions are horizontal length dimensions, while the third relates to depth in the earth formation, which can be represented by a length coordinate, or by a time coordinate such as the two-way travel time of a seismic wave from surface to a certain depth and back. In addition, seismic data are often also acquired for at least two points in time, providing a fourth dimension. This allows changes in the seismic properties of the subsurface to be studied as a function of time. Changes in the seismic properties over time may be due to, for example, spatial and temporal variation in fluid saturation, pressure and temperature.
Seismic monitoring techniques investigate subsurface formations by generating seismic waves in the earth and measuring the time the waves need to travel between one or more seismic sources and one or more seismic receivers. The travel time of a seismic wave is dependent on the length of the path traversed, and the velocity of the wave along the path.
A typical system includes several acoustic receivers deployed across the region of interest. It is not uncommon to use hundreds or even thousands, of acoustic sensors to collect data across a desired area, as illustrated in FIG. 1. The seismic data-containing acoustic signals recorded by the seismic sensors, including reflections from the various layers in a subsurface formation, are known as traces. The recorded acoustic signals are analyzed to derive an indication of the geology in the subsurface. In order to maximize repeatability and therefore sensitivity, the sensors are ideally left in place for the duration of the monitoring period.
Conventional areal seismic monitoring of oil or gas fields has at least two disadvantages. First, it is relatively expensive to acquire, deploy and maintain the large numbers of geophones or hydrophones that are needed in order to monitor a large area for the time periods that are typically involved, which may be on the order of years. Second, because of the transient nature of certain subsurface features, such as fluid flows, the configuration in which the sensors were originally deployed may be suboptimal or even ineffective over time.
For these reasons, it is desirable to provide an areal seismic monitoring system that is inexpensive to acquire, deploy, and maintain, and which can be modified as-needed to optimize data collection with respect to a changing region of interest. Specifically, a changing region of interest may include a part of the subsurface that is of greater importance in improving production of hydrocarbons or because it is undergoing change in acoustic properties as compared to other regions or because it requires different seismic sampling spacing (spatial or temporal) in contrast with other regions.